Combined cycle power plant with integrated CFB devolatilizer and CFB boiler

ABSTRACT

A high efficiency economical coal fired combined cycle power generation system and process is described. The system utilizes a circulating fluid bed (&#34;CFB&#34;) coal devolatilizer which is fluidized with recycled coal volatiles. The devolatilizer is heated indirectly with hot bed material from a conventional CFB boiler burning the devolatilized coal (char). The CFB boiler is fluidized by gas turbine exhaust gas. The ratio of high efficiency/low capital cost Brayton cycle (gas turbine) power output to lower efficiency, higher capital cost Rankine cycle (steam turbine) power output is maximized by concurrently and/or successively preheating the gas turbine compressor discharge with; (1) gas turbine exhaust (recuperator), (2) hot coal volatiles exiting the devolatilizer, (3) coal char CFB boiler hot bed material (with either an external or internal heat exchanger), and (4) CFB boiler flue gas. The process and method described produces a thermally cracked, clean product gas with a high Btu content (˜500 BTU/SCF) and is, therefore, readily usable in gas turbines which are designed for natural gas without design modification. This high Btu product gas also reduces fuel gas cleaning volume and fuel gas sensible heat loss.

RELATED APPLICATIONS

This is a continuation-in-part of application Ser. No. 08/522,763, filedon Sep. 1, 1995, now U.S. Pat. No. 5,666,801, the entire contents ofwhich are incorporated herein by reference.

FIELD OF THE INVENTION

The present invention relates to a high efficiency coal based powergenerating system using circulating fluidized bed ("CFB") technology andprocesses for generating power from volatile containing carbonaceousfeed using such system. More specifically, the present invention relatesto a combined steam and gas turbine power plant that increases thegenerating efficiency of the plant's power by using an indirectlyheated, fully entrained flow circulating fluid bed devolatilizer/thermalcracker. The power plant maximizes the ratio of gas turbine output(Brayton Cycle) to steam turbine output (Rankine Cycle). The presentinvention also relates to processes for generating power from volatilecontaining carbonaceous feeds using such power plant.

BACKGROUND OF INVENTION

Advances in combustion turbines over the past several years have madenatural gas fired, gas turbine, combined cycle plants efficient, cleanand reliable. Because of this, they have become the preferred new powergenerating alternative for locations where natural gas is readilyavailable, e.g., via a pipeline. The cost of power from the new naturalgas combined cycle plants is currently approximately 60% of thatobtained from pulverized coal-based plants of equal or larger scale evenwhere coal is delivered at 60% of the price of natural gas.

Bailie, U.S. Pat. No. 3,853,498, describes an indirectly heated biomassgasifier which uses hot bed material from a stationary (bubbling fluidbed) exothermic char combustor to indirectly dry and devolatilizebiomass fed to an endothermic stationary (bubbling bed) devolatilizer(also known as gasifier or pyrolizer). Because of the high volatilecontent of biomass used in the Bailie process (above 80% by weight),most or all of the char combustion exothermic heat is required to supplythe endothermic requirements of the devolatilizer. For this reasonBailie's biomass gasifier is not suitable for coal. It is not integratedinto a combined cycle power plant.

Feldmann et al., U.S. Pat. No. 4,828,581, describe an improvement overthe Bailie patent for a specific indirectly heated biomassgasifier/devolatilizer vessel design. The '581 patent describes a twozone indirectly heated biomass devolatilizer. The initial fluidizationvelocity, like that of Bailie, is in the stationary or bubbling region(below 7 feet per second (FPS)) using steam or recycled product gas forinitial fluidization. Once high volatile biomass feed is introduced,however, to the top of this first zone, the rapid release of the largequantities of volatiles and moisture intrinsic to biomass producesvelocities (above 15 FPS) sufficient to fully entrain the flow of bedmaterial with residual char. The vessel used in the '581 patent has ahigher length to diameter ratio than Bailie's devolatilizer (above 6:1).It also has a throughput per unit of vessel section area about 10 timesthat noted for stationary (bubbling) bed biomass gasifiers. Use of the'581 patent devolatilizer with coal or integration into a combined cyclepower plant is not described. The two zone devolatilizer vessel designof Feldmann will not work with most coals. This is because coal providesinsufficient moisture and volatile release to raise stationary bed(bubbling) fluidization velocities from below the 7 FPS claimed to above15 FPS necessary for stable entrained flow. Even for those low rank,high moisture content coals where marginally sufficient volatiles may bereleased for entrained flow, a two zone gasifier vessel with "firstspace" velocities below the 7 FPS claimed adds complexity withoutcompensatory advantages. Like Bailie, the vessel is not integrated intoa combined cycle power plant.

Schemenau, U.S. Pat. No. 4,901,521, describes a coal fired combined gasturbine and steam turbine power plant utilizing either a circulatingfluidized bed (CFB) boiler or a bubbling fluid bed boiler. In oneembodiment, hot CFB boiler bed material is directly contacted with onlya portion of the raw coal feed in the CFB bed return conduit. Thistechnique does not create a fluidizing zone. As a result, only a portionof the coal volatiles available for use as gas turbine fuel arerecovered. In another embodiment, a stationary (bubbling bed) coalcombustor (not a CFB) is utilized together with a stationary (bubbling)fluid bed devolatilizer (which they call a degasifier/gasifier) in amanner similar to Bailie, but for coal, not biomass. This devolatilizeris fluidized with boiler exhaust gas containing CO₂ and N₂, thussubstantially diluting the product gas Btu content.

Furthermore, use of a stationary fluid bed devolatilizer in Schemenauresults in an order of magnitude lower throughput. Also, a product gaswith higher tar and condensible liquids content due to less thermalcracking than is possible with CFB devolatilizer results. Schemenau doesnot teach or suggest maximizing the ratio of higher efficiency gasturbine output to lower efficiency steam output because, (1) only aportion, not all of the raw coal is fed directly into the devolatilizer;(2) a portion of turbine exhaust gas sensible heat is not used topreheat turbine air compressor discharge prior to the turbine combustor(recuperator); (3) a portion of product gas sensible heat is not used topreheat gas turbine compressor discharge; (4) a portion of the fluid bedboiler bed material or exhaust gas sensible heat is not used to preheatgas compressor air discharge; (5) the devolatilizer lacks positive gassealing means to prevent a portion of the volatile produced fromescaping to the combustor or its exhaust; and (6) combustible gasproduction is not increased when necessary via the addition of steam andair or oxygen to the devolatilizer.

Gounder, U.S. Pat. No. 5,255,507, describes integrating a coal CFBboiler with a gas turbine cycle and using a recuperator in combinationwith an external fluid bed gas turbine air heater. The '507 patent doesnot, however, describe integrating a coal CFB boiler with adevolatilizer heated indirectly with the CFB boiler's hot bed material.The '507 patent does not teach or suggest maximizing the ratio of gasturbine cycle output to steam turbine cycle output because, (1) aportion of the raw coal is fed directly to the CFB boiler; (2) sensibleheat from the gasifier is not used to preheat gas turbine compressorair; and (3) sensible heat from the CFB boiler exhaust gas is not usedto preheat gas turbine compressor air. In the '507 patent, a portion ofthe gas turbine fuel input is supplied by "a first fuel source" ofnatural gas, not coal gas. When natural gas is available via pipeline,the use of any coal based power technology today is seldom economic (dueto 2 to 3 fold higher capital costs, 20% to 35% lower fuel efficiencyand 2 fold higher operating and maintenance costs, all per Kwh ofelectrical output).

European Patent 607,795 to Dietz describes a CFB unit incorporated intoa combined cycle system in a manner similar to Grounder.

SUMMARY OF THE INVENTION

The present invention relates to a power generating system and process.Volatile containing carbonaceous feed, e.g., coal, fired combined gasturbine cycle (Brayton cycle) and a steam turbine cycle (Rankine cycle)power plant are provided where the gas turbine is fully integrated withboth a conventional coal fully entrained bed ("CFB") boiler and a fullyentrained bed ("CFB") devolatilizer/thermal cracker. Alternatively, thevolatile feed can be pitch, orimulsion, residual or heavy oils, shales,tar sands or biomass. The CFB devolatilizer/thermal cracker of thepresent invention uses the CFB boiler's hot bed material to indirectlysupply the necessary endothermic heat for devolatilizing and crackingcarbonaceous feed, e.g. coal.

The CFB boiler uses gas turbine exhaust gas for all or part of the CFBboiler's fluidizing gas and combustion air supply. Part of the gasturbine's thermal input is provided by the CFB boiler's hot bed materialand hot flue gas, and fuel gas cooling, thus reducing the gas turbinecombustor's fuel requirement and maximizing the ratio of higherefficiency, lower capital cost Brayton cycle power output to lessefficient, higher capital cost Rankine cycle power output.

Alternatively, the ratio of Brayton cycle to Rankine cycle output can bemaximized by using steam and air or oxygen to replace some or all of therecycled product gas as a fluidizing gas in the devolatilizer/thermalcracker. Thus, the product gas yield is increased and the char yieldfrom lower volatile containing feeds reduced. In this embodiment, partof the gas turbine's thermal input is provided via heat exchangers.

The indirectly heated fully entrained flow CFB devolatilizer/thermalcracker is fluidized to entrainment velocities with recirculated crackedcoal volatiles (product gas) thus produced. When lower volatile feedsare used or higher gas yields are desired, steam and air or oxygen areadded to or replace the product gas. The CFB boiler receives thedevolatilized coal or other devolatilized feed (char) and somewhatcooled bed material and combusts the char to reheat the bed material andprovide part of the thermal energy for the Rankine power cycle, andoptionally the Brayton cycle.

Accordingly, an object of the present invention is to overcome thedrawbacks of the prior art by maximizing gas turbine power output tosteam turbine power output for coal of any given volatile content.

A further object of the present invention is to maximize the ratio ofBrayton cycle to Rankine cycle power output by using all available highgrade (high temperature) heat for preheating gas turbine compressor airprior to fuel gas combustion.

A still further object includes recovering heat from the gas turbineexhaust (via a recuperator), hot product gas (thermally cracked coalvolatiles), CFB boiler bed material, and hot CFB boiler flue gas forpreheating gas turbine compressor air.

Another object of the present invention is to fully devolatilize andthermally crack all the carbonaceous feed to generate a product gas forthe power generating system.

Another object of the present invention is to increase more efficientBrayton cycle output, even on lower volatile feeds, by introducing steamand air or oxygen to the devolatilizer. This increases gas productionand reduces char production and is more cost effective than using heatexchangers to transfer heat to the gas turbine (Brayton cycle).

A further object of the present invention is to use the volatile contentof all grades of coals to increase the efficiency of a coal-based powersystem.

A still further object of the present invention is that steam (includingsuper heated and reheated steam) is only generated (with the highestpractical steam cycle efficiency) with excess heat which cannot beeffectively used to preheat gas turbine compressor air prior to beingintroduced into the gas turbine combustor. Another object of the presentinvention is to use all available oxygen in the turbine exhaust in anexothermic reaction with substantially devolatilized carbonaceous feedin the CFB boiler.

Another object of the present invention is to upgrade existing coalbased power systems by using an atmospherically-operated CFBdevolatilizer/thermal cracker with an exothermic boiler combustor and agas turbine fueled by the product gas from the CFB devolatilizer/thermalcracker.

Another object of the present invention is to produce an excess ofproduct gas for export use in chemical plants or general supply (Towngas).

An advantage of using a CFB (entrained flow) devolatilizer/thermalcracker in the present invention is that it has higher throughput andfewer tars and condensible oils than alternative reactors.

A further advantage of using a portion of the char to drive thedevolatilization process is that it preserves all of the cracked coalvolatiles for use as gas turbine topping fuel.

An advantage of the coal devolatilization and thermal cracking processof the present invention, compared to traditional full coal gasificationvia partial oxidation with air or expensive oxygen at atmospheric or gasturbine pressure, is that it has a lower gasification endothermicrequirement while producing gas above 450 Btu/SCF vs. less than 300Btu/SCF for oxygen blown and less than 150 Btu/SCF for air blowngasifiers.

Another advantage according to the present invention is that theresulting product gas is directly substituted for natural gas in mostcommercial gas turbines and the lower gas volume reduces gas compressionenergy loss, sensible heat losses and gas cleaning equipment size andcost.

A still further advantage according to the present invention is the useof alkali sulfur absorbents in the recirculating bed material of the CFBboiler and devolatilizer that provides substantial sulfur capture andeliminates the need for H₂ S removal.

A further advantage of the present invention is that the process can beused either at atmospheric pressure or gas turbine supply pressure. Atgas turbine supply pressure, the turbine exhaust enters a conventionalHRSG and is not utilized as the CFB char combustor air supply. Thepressurized CFB char combustor air supply is thus provided by a portionof the gas turbine air compressor discharge.

A still further advantage of the present invention is that the processcan be conducted with or without a supplemental HRSG when gas turbineexhaust gas output exceeds CFB boiler combustion air requirements orwhen the process is operated in a pressurized mode.

Another advantage of the present invention is that the process can beused with or without CFB boiler external or internal bed gas turbine airpre-heaters.

Features of the present invention include, but are not limited to, theuse of partial supplemental raw coal or other feed to the CFB boilerwhen coal char or other feed char production is insufficient to fullyutilize turbine exhaust for combustion air supply (at expense of someefficiency); the use of partial or full CFB boiler supplementalcombustion air supply when gas turbine exhaust has insufficient O₂ or ifcycle simplicity is desired (at expense of some efficiency); the use ofsteam and/or partial or oxygen air supply to the devolatilizer/thermalcracker or hot product gas stream when (1) additional gas yield andlower char yield is required to maximize gas turbine (Brayton cycle)output, or (2) insufficient heat or temperature for fulldevolatilization or thermal cracking is available via CFB boilerrecirculating hot bed material; the devolatilized cracked high Btuproduct gas can be cooled (via heat exchanger or water quench) andcleaned of particulate, condensibles, and acid gases prior to gasturbine use (after a portion is recycled for devolatilizer fluidizationgas) or hot gas cleaning methods can be used, preserving sensible heatfor improved gas turbine efficiency; and the CFB boiler can be run in areducing (sub-stoichiometric) mode producing CO fuel gas to supplementthe high Btu gas or used indirectly via fired gas turbine air or steamheat exchangers.

Accordingly, one aspect of the present invention relates to a processfor generating power from a carbonaceous feed which comprises the stepsof:

a. providing first and second fully entrained flow circulating fluidizedbed reaction zones through which a loop of heat-conveying materialscontinuously circulate and are fluidized by first and second fluidizinggases, respectively;

b. introducing a volatile-containing carbonaceous feed into the firstfully entrained flow circulating fluidized bed reaction zone;

c. heating the carbonaceous feed with heat-conveying material, for atime period sufficient to produce (1) a product gas comprised ofpartially thermally cracked volatiles and (2) substantiallydevolatilized carbonaceous feed. The heat conveying material enters thefirst reaction zone at a first temperature between about 1000° F. andabout 2400° F. and exits at a second temperature lower than the firsttemperature because of the endothermic heat requirements of the firstreaction zone;

d. separating substantially devolatilized feed and heat-conveyingmaterials from the product gas and recycling some of the product gas asthe majority of the first fluidizing gas;

e. introducing into the second fully entrained flow circulatingfluidized bed reaction zone substantially devolatilized carbonaceousfeed with heat conveying material from step d and, as a secondfluidizing gas, an oxygen containing turbine exhaust gas;

f. exothermically reacting the substantially devolatilized carbonaceousfeed in the presence of the oxygen-containing turbine exhaust gas at atemperature above the temperature of the first reaction zone for a timeperiod sufficient to substantially combust the substantiallydevolatilized carbonaceous feed to produce a flue gas, preheat gasturbine compressed air feed, generate high pressure steam conveyed to asteam turbine to provide power and, elevate the temperature of the heatconveying material from the second temperature to the first temperature;

g. introducing the product gas and air into a gas turbine and combustingthe product gas and air in the gas turbine thereby providing power andproducing an oxygen containing turbine exhaust having a temperature ofat least 800° F. to about 1200° F.; and

h. recycling the oxygen containing turbine exhaust gas of step g to thesecond reaction zone as the second fluidizing gas and the sole orprimary combustion air supply.

In another aspect, the present invention relates to a system, that atleast includes,

a. a first fully entrained flow circulating fluidized bed reactorincluding a circulating bed of heat conveying material fordevolatilizing and thermally cracking volatile containing carbonaceousfeed and being capable of producing substantially devolatilizedcarbonaceous feed and a product gas, said first fully entrained flowcirculating fluidized bed reactor including,

1. an inlet for introducing volatile containing carbonaceous feed to bedevolatilized and thermally cracked;

2. a separator for separating substantially devolatilized feed andcirculating heat conveying material from product gas and including anoutlet for removing separated product gas for heat recovery andscrubbing;

3. a first heat recovery system connected to the outlet for recoveringsensible heat from the product gas;

4. a first recycle line for returning some of the product gas for use aspart of a fluidizing gas for the first fully entrained circulatingfluidized bed reactor;

5. optionally, supplemental ports for introducing steam and/or air oroxygen to increase gas yields and reduce char yields, especially withlower volatile containing feeds; and

b. a second fully entrained flow circulating fluidized bed reactorcontaining a furnace section, a boiler section, a solids/gas separatorsection and, a continuously circulating bed of heat conveying materialthus being capable of conducting an exothermic reaction betweensubstantially devolatilized carbonaceous feed and an oxygen containingturbine exhaust gas to produce flue gas, high pressure steam, preheatedgas turbine compressed air and, reheated heat conveying material to atemperature at or above the first temperature;

c. a first flow line in flow communication with the separator forconveying one portion of the separated substantially devolatilizedcarbonaceous feed and heat conveying material from the first fullyentrained flow circulating fluidized bed reactor into the second fullyentrained flow circulating fluidized bed reactor;

d. a second flow line for conveying heat conveying material from thesecond fully entrained circulating fluidized bed reactor separator intothe first fully entrained circulating fluidized bed reactor;

e. a third flow line for conveying the product gas from the first fullyentrained circulating fluidized bed reactor to a scrubbing system toremove nitrogen and sulfur containing pollutants to produce a cleanedproduct gas;

f. a fourth flow line for conveying a first portion of the cleanedproduct gas to the first fully entrained fluidized circulating bedgasifier and a second portion to a compressor for producing compressedproduct gas for gas turbine fuel for providing power;

g. a gas turbine air compressor for forming a compressed air feed forthe gas turbine combustor and expansion turbine;

h. a fifth flow line for conveying gas turbine compressed air to a gasturbine combustor; and

i. a gas turbine combustor connected to the fourth and fifth conveyinglines for receiving and combusting the second portion of cleaned productgas with compressed air thereby providing a source of power and areusable turbine exhaust, and including a sixth flow line forintroducing the turbine exhaust into the second fully entrained flowcirculating fluidized bed reactor as a fluidizing gas.

These and other objects, advantages, features and aspects of the presentinvention will become more apparent from the following detaileddescription and annexed drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1A and 1B shows a flow chart illustrating a first embodimentaccording to the present invention without preheating the compressed airsupply for the gas turbine combustor. The power generating cycle issimplified at the expense of some overall efficiency loss. If the feedcontains insufficient volatiles to produce enough fuel gas to maximizegas turbine output (Brayton cycle) relative to steam turbine output(Rankine cycle) then supplemental fluidizing steam and/or air or oxygencan be used in the devolitilizer to increase gas output and reduce charoutput via partial oxidation.

FIGS. 2A and 2B shows a flow chart illustrating a preferred embodimentaccording to the present invention where gas turbine (Brayton cycle)power output is maximized and steam turbine (Rankine cycle) output iscorrespondingly reduced by utilizing a significant portion of turbineexhaust heat, product gas sensible heat, CFB boiler bed material heat,and CFB boiler flue gas heat to preheat gas compressor discharge airprior to its introduction into the gas turbine combustor.

DETAILED DESCRIPTION OF INVENTION

The present invention provides a combined cycle power plant ("CCPP")process and an apparatus for its practice. Thus, the present inventionintegrates a CFB boiler burning devolatilized coal char (e.g. reactor,reaction zone), and a CFB coal devolatilizer/thermal cracker (e.g.reactor, reaction zone). The devolatilizer/thermal cracker is heatedindirectly with hot solids recirculated from said CFB coal char burningboiler. It is fluidized to entrainment velocity by recirculating aportion of the thermally cracked coal volatiles. The thermally crackedcoal volatiles fuels the gas turbine. Gas turbine exhaust is used asboth fluidizing gas and a combustion air source for the CFB coal charburning boiler.

In a preferred embodiment of the present invention, gas turbinecompressor air discharge, also referred to as compressed air, (typically600° F. to 700° F.) is preheated. Preheat is provided by gas turbineexhaust (typically 900° F. to 1200° F.) and/or sensible heat from theproduct gas (cracked coal volatiles) and/or the char burning CFB boilerhot bed material and/or exhaust (flue) gas. This maximizes the ratio ofmore efficient, lower capital cost Brayton cycle power output (gasturbine cycle) to less efficient, higher capital cost, Rankine cyclepower output (steam cycle) for coal with a given percent of volatilescontent. As a practical matter, because the char CFB boiler will beoperating with a bed temperature between 1500° F. and 2000° F. and theCFB devolatilizer/thermal cracker at a temperature slightly below that,a significant quantity of product gas must be utilized to reach currentgas turbine maximum firing temperatures of 2350° F. (with 2500° F.proposed for future turbine designs). Heating turbine air compressordischarge above 1200° F. is more suitable for ceramic heat exchangersthan for metal heat exchange surfaces.

Coal volatile content varies significantly with coal grade or rank.Anthracite coal has almost no volatiles and would not be well suited forthe power cycle of the present invention. The carbonaceous feed used inthe present invention should contain over 20% volatiles content toproduce sufficient gas turbine fuel, e.g. product gas. Supplementalsteam and/or air or oxygen can be used to increase gas yield on lowervolatile fuels. There is no upper limit to the volatile content of thecarbonaceous feed which can be used. If with high volatile content feedsthere is insufficient char to achieve optimal steam cycle efficiency forthe CFB boiler, which also serves as the gas turbine heat recovery steamgeneration or HRSG, then supplemental fuel or a portion of the productgas can be used in that boiler. Bituminous coal typically contains from20% to 30% volatiles by weight and could be satisfactorily utilized. Ifcombustion of bituminous coal volatiles produced provides insufficientgas turbine exhaust to meet all of the CFB char boiler's combustion airsupply requirements, supplemental combustion air may be added.

Regardless of coal volatile content, there will always be sufficientcoal volatiles to fluidize the CFB devolatilizer/thermal cracker to afully entrained flow velocity by simply increasing the portion of theproduct gas recycled and/or using supplemental steam and air or oxygen.Fluidization velocities characterizing bubbling or stationary fluid bedsand circulating or entrained beds are governed by bed particle size anddensity. For the type of reactors, e.g., combustors and gasifiers thatrelate to the subject invention, particle size and densities wouldgenerally result in bubbling beds below 5 ft./sec., fully entrained orCFB flows above 15 ft./sec. and transitional and sometimes unstableflows between 5 and 15 ft. sec. Suitable entrained flow velocities forthis invention are between 10 and 50 ft./sec. and preferably 20 to 40ft./sec. Above 50 ft./sec., severe erosion of reactors and cyclones canoccur.

Lower ranking coals like sub-bituminous coal, lignite, and peat haveprogressively higher volatile content. While the subject invention isdescribed with various coals, suitable volatile containing carbonaceousfeeds may also include orimulsion, oil shale, tar sands and biomass. Ifthe present devolatilization method for high volatile feeds results intoo much gas turbine fuel and consequently too much turbine exhaust tobe effectively used as char CFB boiler fluidizing gas and combustion air(while preserving minimum excess air for good boiler efficiency), thenpart of the turbine exhaust can be taken to a heat recovery steamgenerator (HRSG). A less costly, although somewhat less efficientalternative would be to add some raw coal to the CFB char burningboiler, increasing the boiler combustion air requirements such that itcould be fully satisfied by the gas turbine exhaust (gas turbine exhausttypically contains approximately 15% O₂ which is more than adequate forCFB boiler combustion air supply).

Further, by using turbine exhaust produced according to the presentinvention or even from a conventional natural gas fired turbine for theCFB boiler combustion air supply, greater O₂ utilization (lower excessair) and higher boiler efficiency are obtained. Turbine exhaust suppliedto a fully-fired CFB boiler combustor will also produce lower NO_(x)emissions compared to a conventional air supplied CFB boiler due to theflue gas recirculation effects of lower O₂ turbine exhaust (12%-15% O₂versus 20%).

The CFB char burning boiler and CFB devolatilizer/thermal cracker of thepresent invention can be operated at about atmospheric pressure (15 to30 psia) or at the gas turbine fuel supply pressure (typically 10 to 30atmospheres). The differential pressure between the two reactors wouldtypically be kept to less than 1 atmosphere to avoid the loss of gassealing between the two vessels and gas leakage from one to the other.If operated at high pressure, the turbine is exhausted to an atmosphericHRSG and the CFB char burner combustion air is supplied by the gasturbine air compressor or a separate air compressor.

The process can be operated with and without a supplemental HRSG. It canbe operated with or without supplemental air supply or supplemental coalsupply to the CFB char burning boiler. It can be operated with orwithout a recuperator and with or without gas turbine air preheaters.

If the CFB devolatilizer/thermal cracker operating temperature isinsufficient to get adequate devolatilization and/or cracking or gasyields, steam and/or air or oxygen can be added with or substituted forthe fluidizing recycled product gas to boost temperature and/or gasyields with only a minor dilution in product gas heating value. The CFBchar burning boiler can also be operated at sub-stoichiometricconditions to produce Co rather than CO₂ (both diluted with N₂). Thislow Btu CO fuel gas can be cleaned, compressed and mixed with high Btuproduct gas and be burned in the gas turbine or, alternatively, it canbe burned separately in a fired heater to either preheat gas turbinecompressed air or to produce high pressure super-heated steam. As usedherein, "low BTU gas" refers to a gas with less than 150 BTU/SCF, on ahigher heating basis. By "medium BTU gas" is meant a gas with 150 to 350BTU/SCF on a higher heating basis. A "high BTU gas" is a gas with above350 BTU/SCF on a higher heating basis.

The heat-conveying bed material according to the present invention canbe inert refractory material (e.g., sand, quartz, silica, glass, etc.),an alkali absorbent (e.g., limestone, dolomite) or a supported catalyst.Because the subject invention can utilize a conventional CFB coal boiler(having a boiler section, entrained bed combustion section andsolids/gas separator section) and a conventional commercially availablegas turbine, an existing CFB coal boiler can, therefore, be repoweredwith an increase in efficiency and out-put via the addition of a CFBcoal devolatilizer/thermal cracker and a gas turbine (essentially asshown in FIG. 1). The only non-commercial equipment involved inrepowering an existing CFB boiler with the subject technology would bethe CFB coal devolatilizer/thermal cracker which, due to its highthroughput, is small, simple to construct, and relatively low in cost.

Many gas turbines have expander capacity which is 10% to 25% larger thantheir air compressor capacity. When such gas turbines are utilized,clean product gas can be moisturized utilizing available low gradesensible waste heat from product gas cooling or CFB boiler flue gascooling. This technique can increase turbine output by up to 20% withsome concurrent heat rate improvement.

According to the present invention, the residence time in thedevolatilizer is for a time period sufficient, between 0.5 to 5 seconds,to produce (1) a product gas comprised of partially thermally crackedvolatiles and (2) substantially devolatilized solid carbonaceous feed.The partially cracked volatiles provide some of the first fluidizinggas. The heat-conveying material enters the CFB devolatilizer/thermalcracker at a first temperature between about 1000° F. and about 2400° F.and exits at a second temperature lower than the first temperaturebecause of the endothermic heat requirements of the first reaction zone(CFB devolatilizer/thermal cracker). The devolatilized solids'temperature at which CFB devolatilizer/thermal cracker is operated isabove about 1000° F., preferably above about 1400° F. and mostpreferably above about 1700° F. Moreover, the devolatilized solids'temperature is below about 2400° F., preferably below about 2200° F. andmost preferably about 2000° F. Operating the CFB devolatilizer/thermalcracker at temperatures below 1000° F. will provide poordevolatilization of the carbonaceous feed material and result ininadequate thermal cracking. At temperatures above 2400° F., slaggingand fusing of ash will occur in the CFB devolatilizer/thermal cracker.

The CFB boiler of the present invention exothermically reacts thesubstantially devolatilized feed from the CFB devolatilizer/thermalcracker in the presence of the oxygen-containing turbine exhaust gas.The reaction occurs at a temperature above the temperature of the CFBdevolatilizer/thermal cracker. The exothermic reaction occurs over atime period sufficient to substantially combust the substantiallydevolatilized feed and produce a flue gas. The hot flue gas and bedmaterial is used to preheat turbine air and generate high pressure steamand, with the heat liberated by the exothermic reaction, elevate thetemperature of the heat conveying material from the second temperatureto a temperature greater than or equal to the first temperature.

In the gas turbine according to the present invention, cleaned productgas and compressed air are combusted and form a turbine exhaust that hasa temperature of at least 800° F. to about 1200° F. and also containssufficient oxygen for use in a CFB boiler.

The systems shown in FIGS. 1A, 1B, 2A and 2B include flow lines for thematerials being transferred between the various treatment stages. Theseflow lines will include the necessary valves and flow control devicesknown to those skilled in the art to assist in the transfer of solidsand/gases between treatment stages, although they are not shown. Wherenecessary, pumps, compressors and blowers also will be used, theirplacement and capacities being within the skill of a practitioner of theart.

The present invention will now be described with reference to FIGS. 1A,1B, 2A and 2B.

In FIGS. 1A and 1B raw coal or other volatile containing carbonaceousfeed, previously crushed to a size consistent with entrained flow or CFBreactors (used synonymously), typically below 1/4" maximum particlesize, is introduced through a low pressure type sealed feeder such as arotary lock hopper, star valve, or other pressure sealed feeder such asthose in commercial use on existing CFB boilers. The feed material isintroduced through one or more feed ports (12) into the bottom of anentrained flow CFB reactor (10). The reactor (10) is refractory linedand insulated. Hot heat conveying material from the CFB boiler system(30) through line (45) is fed into the bottom of said CFBdevolatilization/thermal cracking reactor (10) through one or more feedports (16). The feed material and hot solid heat conveying bed materialare conveyed upward in entrained flow through the reactor (10) bytransport gas which is recycled product gas (24), which may besupplemented or replaced with steam and/or air or oxygen for enhancedgas production. The transport gas is introduced through the bottom ofreactor (10) through line (40) and through a perforated distributorplate (not shown) common to commercial CFB boilers and reactors. As thehot solid heat conveying materials and raw feed material are transportedup the reactor (10) at a velocity sufficient to maintain stableentrained flow (above 10 ft/second and preferably above 15 ft/second),heat in the hot bed material is transferred to the raw feed material bya combination of conduction, convection, and radiation heat transfermodes. Volatiles are thereby driven out of the feed material and atleast partially thermally cracked into lower molecular weightnon-condensible gases (product gas).

The solids are removed from the top of the reactor (10) and are passedto a solids gas separation system (14) which can be one or more cyclonetype separators, labyrinth type separators (U-beams or chevrons), orsimilar devices commonly used on CFB boiler systems in commercial use.The hot product gas is removed from the separator (14) passed throughline (18) where some of its heat may be exchanged indirectly in aproduct gas reheater (20) where cold, clean product gas used for CFBdevolatilizer fluidization gas through line (40) is reheated. Cooledproduct gas line (18) is then conveyed through a product gas quenchingand cleaning system (22) of conventional design, removing H₂ Sparticulate and condensible liquids. The cleaned product gas from system(22) is split and a portion of the product gas is recycled through line(24) where its pressure is boosted by a low pressure blower (26)sufficiently to be utilized as fluidizing gas in reactor (10). The majorportion of product gas from gas cleaning system (22) is compressed in ahigh pressure gas compressor (58) before it is passed to the gas turbinecombustor (56).

Solids that are discharged from separator (14) are somewhat cooler thanthose that are fed to the devolatilizer through line (45). This isbecause of the endothermic devolatilization and cracking reactions plusendothermic heat requirements necessary for evaporation of any moistureassociated with the raw feed material and heat up feed material toreactor temperature (plus losses through equipment insulation). Theseparated solids from system (14) include both solid heat conveyingmaterial and residual char. This material is unfluidized in theseparator bottom and a connected unfluidized stand-pipe (15). Thismaterial is conveyed through line (19) by a controlled L-valve, J-valve,or other commercially available solids recirculation control valve (17)in common use on CFB boilers and similar fluidized systems. The cooledheat conveying material with char is introduced into the CFB boilersystem furnace (reaction zone 32) through one or more feed ports (34) inthe bottom of furnace (32). The CFB boiler system (30) is ofconventional commercial design and can have either refractory linedinsulated walls or be lined with steam generating water tubes (waterwall construction). Hot heat conveying material recirculated within theCFB boiler system is fed to the bottom of the CFB furnace (32) via oneor more ports (36). Gas turbine exhaust is used as fluidizing gas forthe CFB boiler furnace (32) and is introduced through line (62) througha distributor plate (not shown) of conventional design located at thebottom of the CFB boiler furnace (32).

If turbine exhaust provides insufficient O₂ for efficient burning ofchar in the CFB boiler system (30), supplemental combustion air can beadded through line (64). If insufficient char is produced in thedevolatilizer (10) to efficiently utilize the quantity of O₂ containedin the gas turbine exhaust line (62), then supplemental coal feed can beadded to the CFB boiler furnace (32) through line (66) to maintain goodboiler efficiency.

Solids and gases are discharged through the top of the CFB boilerfurnace (32) and are introduced into a gas/solids separator (38).Separated gases are ducted to a conventional convective boiler section(40) containing superheaters, reheaters, steam generators, andeconomizers. Separated solids from separator (38) are introduced into anunfluidized standpipe (39) where they are redirected either to the CFBdevolatilizer/thermal cracker reactor (10) via line (45) through asolids circulation control valve (41) or recirculated back to the CFBboiler furnace (32) through a second solids circulation control valve(42). Superheated steam from the CFB boiler system is conveyed throughline (44) to a conventional steam turbine generator (70) for powergeneration utilizing a Rankine cycle type system. This system includes acondenser and cooling tower and may or may not contain several stages ofre-heat and feedwater heating common to such systems. CFB boiler fluegases are discharged from the boiler convective section (40) throughline (46) and are passed through typical pollution control equipment anda stack prior to venting to the atmosphere.

Clean, compressed fuel gas is introduced into a conventional commercialgas turbine combustor (56) through line (57). The conventional gasturbine also contains a compressor section (50) and a turbine section(52) which drives both the compressor and a generator that makeselectrical power.

In FIGS. 1A and 1B, a cycle efficiency is maximized by using feeds withhigh volatile content or by increasing devolatilizer gas production suchthat 50% to 75% of feed energy is converted to turbine (Brayton cycle)gas or liquid fuel and char production is limited to that needed for bedsand reheating and production of high pressure reheated steam to alsomaximize cycle efficiency.

In FIGS. 2A and 2B, an alternative embodiment of the invention, thermalheat is recovered at several locations for pre-heating gas turbinecompressor air, i.e., compressed air, to the maximum possibletemperature prior to burning fuel gas. This maximizes the ratio of moreefficient gas turbine (Brayton cycle) power output to less efficientsteam turbine (Rankine cycle) power output. A common numbering systemwith FIGS. 1A and 1B is used for common elements except for the prefix"1".

Feed and operation of the CFB devolatilizer/thermal cracker (reactor) isunchanged from the system described for FIGS. 1A and 1B. As in FIG. 1,cooled heat conveying solid bed material and char from thedevolatilizer/thermal cracker (110) is conveyed via line (115) throughentrance port(s) (134) to the CFB boiler furnace section (132). Furnaceheat-conveying solids and gases are then passed through a solids gasseparator (138). A portion of the separated hot solids in the insulatedstandpipe (139) are recirculated back to the CFB devolatilizer/thermalcracker (110) through solids control valve (141) and line (145). Theremaining heat conveying solids are conveyed to an external fluid bedturbine air heater (148) after passing through solids circulationcontrol valve (142) and line (136).

Compressed turbine air preheated in a recuperator (166) is passed vialines (167) to the external fluid bed air heater (148). The externalfluid bed turbine air heater (148) is fluidized to stationary fluid bedvelocity (less than 7 ft/sec and preferably less than 5 ft/sec) with aportion of gas turbine exhaust gas conveyed via lines (162) and (163).Preheated air in line (169), elevated in temperature, is returned to theturbine combustor via line (165). This external fluid bed air heater issimilar to external fluid bed superheaters currently in use oncommercially available CFB boilers. Somewhat cooled bed material exitingthe external fluid bed air heater is introduced into the bottom of theCFB boiler furnace (132) through one or more entrance ports (135).

CFB boiler flue gases exit the particle separator (138) and areintroduced into the boiler convective section (140). The flue gasses arefirst cooled by transferring heat to an additional gas turbinecompressed air heater (143) that is supplied with compressed air fromline (167). The heated compressed air returns to the gas turbinecombustor via lines (169) and (165).

Hot cracked volatiles (product gas) from the CFB devolatilizer/thermalcracker (110) via line (118) are first cooled in an additional turbinecompressed air heater (119) that is supplied with gas turbine compressedair from supply line (167) and heated compressed air is returned to line(165). Cooler product gas is removed from air heater (119) and isfurther cooled in a boiler (121) that generates high pressuresuperheated steam. This steam is conveyed to the steam turbine (170) vialine (144). The product gas is then further quenched and cleaned andconveyed to the gas turbine as described in FIGS. 1A and 1B.

The amount of heat recovery available through all of the gas turbinecompressed air heaters (148, 143, and 119) is limited by materialconsiderations. Metal tubing currently utilized on steam boilersuperheaters is limited to about 1100° F. High temperature metal alloysand ceramics under development will allow higher temperatures.Preheating turbine air to temperatures approaching the CFB boiler bedmaterial temperatures (typically 1800° F. to 2000° F.) allows asubstantially larger portion of the total system heat to be utilized inthe more efficient gas turbine cycle rather than the less efficientsteam turbine cycle.

With higher volatile feeds, it is possible to produce more product gasfor use in the gas turbine and, therefore, it is possible to producemore turbine exhaust than can be efficiently utilized in the CFB boiler(130) while maintaining the minimum excess air required (typically lessthan 20% above stoichiometric O₂ requirements) for good boilerefficiency. Rather than suffer poor boiler efficiency, one alternativedescribed in FIG. 2 is where supplemental raw coal feed is directlyintroduced into the CFB boiler furnace (132) through line (166) aspreviously described. A more desirable alternative, however, is wherethe excess portion of turbine exhaust is conveyed through line (179) toa conventional heat recovery steam generator (HRSG) (180) common incommercial gas turbine combined cycle power plants, prior to taking suchcooled gas turbine exhaust to an exhaust stack. High pressure andintermediate pressure steam from the HRSG (180) is utilized in the steamturbine through lines (182) and (184).

Although the invention has been described in conjunction with a specificembodiment, many alternatives and variations will be apparent to thoseskilled in the art in light of this description and the annexeddrawings. Accordingly, the invention is intended to embrace all of thealternatives and variations that fall within the spirit and scope of theappended claims. Further, the subject matters of the above-cited UnitedStates patents are incorporated herein by reference.

What is claimed is:
 1. A process for generating power from a volatilecontaining carbonaceous feed, comprising:a. providing first and secondfully entrained flow circulating fluidized bed reaction zones throughwhich a loop of heat-conveying materials continuously circulate andbeing fluidized by first and second fluidizing gases, respectively; b.introducing a volatile-containing carbonaceous feed into said firstfully entrained flow circulating fluidized bed reaction zone; c. heatingsaid volatile containing carbonaceous feed with said heat-conveyingmaterials, for a time period sufficient to produce a product gascomprised of partially thermally cracked volatiles and substantiallydevolatilized feed, said heat-conveying material entering the firstreaction zone at a first temperature between about 1000° F. and about2400° F. and exiting at a second temperature lower than said firsttemperature because of the endothermic heat requirements of said firstreaction zone; d. separating said substantially devolatilized feed withsaid heat-conveying materials from said product gas; e. eitherincreasing product gas yield or devolatilization reaction temperature instep c by substituting steam and/or air or oxygen as the fluidizing gas;f. introducing into said second fully entrained flow circulatingfluidized bed reaction zone said substantially devolatilized feedtogether with said heat-conveying material from step e and, as saidsecond fluidizing gas, an oxygen containing turbine exhaust gas; g.exothermically reacting said substantially devolatilized feed in thepresence of said oxygen-containing turbine exhaust gas at a temperatureabove the temperature of said first fully entrained flow circulatingfluidized reaction zone for a time period sufficient to substantiallycombust said substantially devolatilized feed, produce a flue gas,preheat a compressed air feed for a gas turbine, generate high pressuresteam conveyed to a steam turbine to provide power and elevate thetemperature of said heat-conveying material from said second temperatureto a temperature equal to or greater than said first temperature; h.separating elevated temperature heat conveying material in step g andconveying a portion of said elevated temperature heat conveying materialto said first reaction zone; i. compressing a portion of said productgas from step e and forming a compressed product gas; j. providingcompressed air from a gas turbine compressor; k. introducing saidcompressed product gas and said compressed air into a gas turbinecombustor, combusting said compressed product gas and said compressedair in said gas turbine thereby providing power and an oxygen containingturbine exhaust having a temperature of at least 800° F. to about 1200°F.; and l. recycling said oxygen containing turbine exhaust gas of stepk to said second fully entrained flow circulating fluidized reactionzone as said second fluidizing gas.
 2. The process according to claim 1,wherein said fully entrained flow circulating fluidized bed reactionzones are respectively operated at or above the gas turbine operatingpressure.
 3. The process according to claim 1, wherein said volatilecontaining feed is biomass.
 4. The process according to claim 1, whereinsaid volatile containing feed is Orimulsion.
 5. The process according toclaim 1, wherein said volatile containing feed is residual or heavycrude oil.
 6. The process according to claim 1, wherein said volatilecontaining feed is pitch.
 7. The process according to claim 1, furtherincluding the step of introducing steam and/or air or oxygen assupplemental or replacement fluidizing gas into said fully entrainedflow circulating fluidized bed reaction zones to increase gas yield. 8.A process for generating power from a volatile containing carbonaceousfeed, comprising:a. providing first and second fully entrained flowcirculating fluidized bed reaction zones through which a loop ofheat-conveying materials continuously circulate and being fluidized byfirst and second fluidizing gases, respectively; b. introducing avolatile-containing carbonaceous feed into said first circulatingfluidized bed reaction zone; c. heating said feed with saidheat-conveying materials, for a time period sufficient to produce aproduct gas comprised of partially thermally cracked volatiles andsubstantially devolatilized feed, said heat-conveying material enteringthe first reaction zone at a first temperature between about 1000° F.and about 2400° F. and exiting at a second temperature lower than saidfirst temperature because of the endothermic heat requirements of saidfirst reaction zone; d. separating said substantially devolatilized feedwith said heat-conveying materials from said product gas and, recyclingsome of said product gas for use as said first fluidizing gas; e. eitherincreasing product gas yield or devolatilization reaction temperature instep c by substituting steam and/or air or oxygen as the fluidizing gas;f. introducing into said second circulating fluidized bed reaction zonesaid substantially devolatilized feed together with said heat-conveyingmaterial from step e and, as said second fluidizing gas, an oxygencontaining turbine exhaust gas; g. exothermically reacting saidsubstantially devolatilized feed in the presence of saidoxygen-containing turbine exhaust gas at a temperature above thetemperature of said first reaction zone for a time period sufficient tosubstantially combust said substantially devolatilized feed, produce aflue gas, preheat compressed air for a gas turbine, generate highpressure steam and, elevate the temperature of said heat- conveyingmaterial from said second temperature to a temperature greater than saidfirst temperature, said high pressure steam being conveyed to a steamturbine to provide power; h. separating said re-elevated temperatureheat-conveying material into first and second portions, said firstportion being conveyed to said first reaction zone as saidheat-conveying material; i. providing compressed air from a compressorsection of a gas turbine; j. providing a recuperator and introducingsaid compressed air of step i into said recuperator in heat exchangerelationship with turbine exhaust from a gas turbine therebytransferring heat from said turbine exhaust to said compressed air insaid recuperator to form preheated compressed air at a firsttemperature; k. providing a first air heater; introducing a portion ofsaid compressed air of step i at said first temperature into said firstair heater; and introducing product gas of step e into said first airheater thereby transferring heat from said product gas to elevate thetemperature of said portion of preheated compressed air at said firsttemperature to a second temperature higher than said first temperature;l. providing a fluidized bed air heater, introducing another portion ofsaid preheated compressed air from step i at said first temperature intosaid fluidized bed air heater, introducing and fluidizing said separatedsecond portion of heat-conveying material from step h into saidfluidized bed air heater thereby transferring heat from said secondportion of separated heat-conveying material to elevate the temperatureof said another portion of preheated compressed air at said firsttemperature in said fluidized bed heater to a third temperature higherthan said first temperature; m. providing a second compressed air heaterin a convective boiler section of said second circulating bed reactionzone, introducing a further portion of said preheated compressed air ofstep i into said second air heater whereby heat in said flue gasgenerated in said second fully entrained flow circulating fluidized bedzone transfers heat to said further portion of said compressed air insaid second air heater to form preheated compressed air at a fourthtemperature higher than said first temperature; n. providing acompressed product gas; o. providing a gas turbine; introducing saidcompressed product gas of step m and said preheated compressed airportions from steps j, k, l and m into said gas turbine, combusting saidcompressed product gas and said preheated compressed air portions insaid gas turbine thereby providing power and an oxygen containingturbine exhaust having a temperature of at least 800° F. to about 1200°F. that is used as said turbine exhaust of step i; and p. recycling saidoxygen containing turbine exhaust gas of step o to said second fullyentrained flow circulating fluidized bed reaction zone as said secondfluidizing gas.